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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

x

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

 

for the quarterly period ended June 30, 2011

 

 

OR

 

 

o

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

 

for the transition period from              to              

 

Commission file number: 000-50536

 

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

52-2235832

(State of organization)

 

(I.R.S. Employer Identification No.)

 

 

 

2501 CEDAR SPRINGS

 

 

DALLAS, TEXAS

 

75201

(Address of principal executive offices)

 

(Zip Code)

 

(214) 953-9500

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o      No x

 

As of July 22, 2011, the Registrant had 47,181,084 shares of common stock outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Item

 

Description

 

Page

 

 

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

 

 

1.

 

Financial Statements

 

3

 

 

 

 

 

2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

22

 

 

 

 

 

3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

33

 

 

 

 

 

4.

 

Controls and Procedures

 

36

 

 

 

 

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

 

 

1.

 

Legal Proceedings

 

36

 

 

 

 

 

1A.

 

Risk Factors

 

36

 

 

 

 

 

6.

 

Exhibits

 

36

 

2



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Balance Sheets

 

 

 

June 30,

 

December 31,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

7,012

 

$

22,780

 

Accounts and notes receivable, net:

 

 

 

 

 

Trade receivable

 

21,689

 

16,351

 

Accrued revenue and other

 

198,968

 

193,647

 

Fair value of derivative assets

 

4,811

 

5,523

 

Natural gas and natural gas liquids, prepaid expenses and other

 

13,835

 

9,780

 

Total current assets

 

246,315

 

248,081

 

Property and equipment, net of accumulated depreciation of $368,971 and $329,741, respectively

 

1,226,696

 

1,216,166

 

Fair value of derivative assets

 

88

 

1,169

 

Intangible assets, net of accumulated amortization of $173,830 and $151,735, respectively

 

476,880

 

498,975

 

Investment in limited liability company

 

34,764

 

 

Other assets, net

 

26,446

 

26,712

 

Total assets

 

$

2,011,189

 

$

1,991,103

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable, drafts payable, and other

 

$

26,834

 

$

18,027

 

Accrued gas purchases

 

163,011

 

160,910

 

Fair value of derivative liabilities

 

8,303

 

7,980

 

Current portion of long-term debt

 

 

7,058

 

Other current liabilities

 

66,450

 

66,887

 

Total current liabilities

 

264,598

 

260,862

 

Long-term debt

 

764,460

 

711,512

 

Other long-term liabilities

 

25,416

 

26,879

 

Deferred tax liability

 

87,412

 

89,216

 

Fair value of derivative liabilities

 

185

 

1,156

 

Commitments and contingencies

 

 

 

Stockholders’ equity

 

869,118

 

901,478

 

Total liabilities and stockholders’ equity

 

$

2,011,189

 

$

1,991,103

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Statements of Operations

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands, except per share amounts)

 

Revenues

 

$

496,147

 

$

442,048

 

$

946,462

 

$

910,706

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

Purchased gas and NGLs

 

399,589

 

358,038

 

760,068

 

745,501

 

Operating expenses

 

27,913

 

25,424

 

52,957

 

51,889

 

General and administrative

 

13,272

 

12,455

 

25,754

 

25,936

 

(Gain) loss on sale of property

 

(60

)

564

 

(80

)

(13,779

)

Loss on derivatives

 

1,536

 

1,594

 

4,957

 

5,290

 

Impairments

 

 

313

 

 

1,311

 

Depreciation and amortization

 

31,654

 

26,840

 

61,326

 

53,950

 

Total operating costs and expenses

 

473,904

 

425,228

 

904,982

 

870,098

 

Operating income

 

22,243

 

16,820

 

41,480

 

40,608

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense, net of interest income

 

(20,674

)

(19,995

)

(40,440

)

(46,850

)

Loss on extinguishment of debt

 

 

 

 

(14,713

)

Other income (expense)

 

(242

)

23

 

(130

)

205

 

Total other income (expense)

 

(20,916

)

(19,972

)

(40,570

)

(61,358

)

Income (loss) before non-controlling interest and income taxes

 

1,327

 

(3,152

)

910

 

(20,750

)

Income tax benefit

 

248

 

1,204

 

898

 

3,789

 

Net income (loss)

 

1,575

 

(1,948

)

1,808

 

(16,961

)

Less: Net income (loss) attributable to the non-controlling interest

 

2,648

 

233

 

4,417

 

(9,378

)

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,073

)

$

(2,181

)

$

(2,609

)

$

(7,583

)

Net loss per common share:

 

 

 

 

 

 

 

 

 

Basic common share

 

$

(0.02

)

$

(0.05

)

$

(0.05

)

$

(0.16

)

Diluted common share

 

$

(0.02

)

$

(0.05

)

$

(0.05

)

$

(0.16

)

Weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

47,140

 

46,598

 

47,108

 

46,571

 

Diluted

 

47,140

 

46,598

 

47,108

 

46,571

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Comprehensive Income

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Net income (loss)

 

$

1,575

 

$

(1,948

)

1,808

 

(16,961

)

Change in Non-controlling interest’s portion of accumulated other comprehensive income due to the issuance of units by Partnership, net of taxes of $68

 

 

 

 

115

 

Hedging losses reclassified to earnings, net of taxes of $70, $32, $108 and $172, respectively

 

119

 

53

 

184

 

291

 

Adjustment in fair value of derivatives, net of taxes of $(14), $61, $(152) and $102, respectively

 

(24

)

103

 

(258

)

173

 

Comprehensive income (loss)

 

1,670

 

(1,792

)

1,734

 

(16,382

)

Less: Comprehensive income (loss) attributable to the non-controlling interest

 

2,648

 

233

 

4,417

 

(9,378

)

Comprehensive loss attributable to Crosstex Energy, Inc.

 

$

(978

)

$

(2,025

)

$

(2,683

)

$

(7,004

)

 

See accompanying notes to condensed consolidated financial statements.

 

5



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Changes in Stockholders’ Equity

Six Months Ended June 30, 2011

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

Additional

 

Retained

 

Other

 

Non-

 

 

 

 

 

Common Stock

 

Paid in

 

Earning

 

Comprehensive

 

Controlling

 

 

 

 

 

Shares

 

Amount

 

Capital

 

(Deficit)

 

Income (loss)

 

Interest

 

Total

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Balance, December 31, 2010

 

46,894

 

$

468

 

$

242,390

 

$

(58,298

)

$

(145

)

$

717,063

 

$

901,478

 

Stock-based compensation

 

 

 

1,820

 

 

 

2,295

 

4,115

 

Common dividends

 

 

 

 

(8,192

)

 

 

(8,192

)

Net income (loss)

 

 

 

 

(2,609

)

 

4,417

 

1,808

 

Conversion of restricted stock for common, net of shares withheld for taxes

 

283

 

3

 

(1,022

)

 

 

 

(1,019

)

Hedging gains or losses reclassified to earnings

 

 

 

 

 

184

 

796

 

980

 

Adjustment in fair value of derivatives

 

 

 

 

 

(258

)

(1,126

)

(1,384

)

Non-controlling partner’s impact of conversion of restricted units and options exercise

 

 

 

 

 

 

(1,348

)

(1,348

)

Distribution to non-controlling interest

 

 

 

 

 

 

(27,320

)

(27,320

)

Balance, June 30, 2011

 

47,177

 

$

471

 

$

243,188

 

$

(69,099

)

$

(219

)

$

694,777

 

$

869,118

 

 

See accompanying notes to condensed consolidated financial statements.

 

6



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Cash Flows

 

 

 

Six Months Ended June 30,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

1,808

 

$

(16,961

)

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

 

 

 

 

 

Depreciation and amortization

 

61,326

 

53,950

 

Gain on sale of property

 

(80

)

(13,779

)

Impairments

 

 

1,311

 

Deferred tax benefit

 

(2,009

)

(4,688

)

Non-cash stock-based compensation

 

4,115

 

5,367

 

Derivatives mark to market interest rate settlement

 

 

(24,160

)

Non-cash portion of derivatives (gain) loss

 

828

 

(581

)

Non-cash portion of loss on debt extinguishment

 

 

5,396

 

Payment of interest paid-in-kind debt

 

 

(11,558

)

Amortization of debt issue costs

 

4,065

 

3,751

 

Amortization of discount on notes

 

948

 

738

 

Equity in loss of limited liability company

 

236

 

 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, accrued revenue and other

 

(10,657

)

24,142

 

Natural gas and natural gas liquids, prepaid expenses and other

 

(5,378

)

1,212

 

Accounts payable, accrued gas purchases and other accrued liabilities

 

8,640

 

(8,112

)

Net cash provided by operating activities

 

63,842

 

16,028

 

Cash flows from (used in) investing activities:

 

 

 

 

 

Additions to property and equipment

 

(49,643

)

(18,632

)

Insurance recoveries on property and equipment

 

 

874

 

Proceeds from sale of property

 

107

 

59,484

 

Investment in limited liability company

 

(35,000

)

 

Net cash provided by (used in) investing activities

 

(84,536

)

41,726

 

Cash flows from (used in) financing activities:

 

 

 

 

 

Proceeds from borrowings

 

277,250

 

893,112

 

Payments on borrowings

 

(232,308

)

(1,040,405

)

Payments on capital lease obligations

 

(1,510

)

(1,114

)

Increase (decrease) in drafts payable

 

3,165

 

(1,595

)

Debt refinancing costs

 

(3,792

)

(28,485

)

Conversion of restricted stock, net of shares withheld for taxes

 

(1,019

)

(84

)

Distributions to non-controlling partners in the Partnership

 

(27,320

)

(3,314

)

Common dividend paid

 

(8,192

)

 

Conversion of resticted units, net of units withheld for taxes

 

(1,740

)

(1,725

)

Proceeds from exercise of Partnership unit options

 

392

 

233

 

Proceeds from issuance of Partnership units

 

 

120,786

 

Net cash provided by (used in) financing activities

 

4,926

 

(62,591

)

Net decrease in cash and cash equivalents

 

(15,768

)

(4,837

)

Cash and cash equivalents, beginning of period

 

22,780

 

10,703

 

Cash and cash equivalents, end of period

 

$

7,012

 

$

5,866

 

Cash paid for interest

 

$

35,936

 

$

29,449

 

Cash paid for income taxes

 

$

752

 

$

2,647

 

 

See accompanying notes to condensed consolidated financial statements.

 

7



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

June 30, 2011

(Unaudited)

 

(1) General

 

Unless the context requires otherwise, references to “we,” “us,” “our,” “CEI” or the “Company” mean Crosstex Energy, Inc. and its consolidated subsidiaries.

 

Crosstex Energy, Inc., a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs). The Company connects the wells of natural gas producers in the geographic areas of its gathering systems in order to gather for a fee or purchase the gas production, processes natural gas for the removal of NGLs, transports natural gas and NGLs and ultimately provides natural gas and NGLs to a variety of markets. In addition, the Company purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.

 

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership.  The Partnership is included because CEI controls the general partner of the Partnership.

 

(a) Basis of Presentation

 

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the consolidated financial statements for the prior year to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2010.

 

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

 

(b) Investment in Limited Liability Company

 

On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners (“HEP”) for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP of approximately 35.0%.  In addition to the Partnership’s contribution, an unrelated party also provided a capital contribution of $35.0 million for a 35.0% ownership in HEP with HEP management and a few private investors owning the remaining 30.0% interest.  HEP will operate and manage midstream services as well as pipeline and plant construction primarily in the Eagle Ford Shale in south Texas.  This investment in HEP will be accounted for under the equity method accounting and is reflected on the balance sheet as “Investment in limited liability company.”

 

(2) Long-Term Debt

 

As of June 30, 2011 and December 31, 2010, long-term debt consisted of the following (in thousands):

 

 

 

June 30,

 

December 31,

 

 

 

2011

 

2010

 

Bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2011 and December 31, 2010 was 2.68% and 4.0%, respectively

 

$

52,000

 

$

 

Senior unsecured notes (due 2018), net of discount of $12.5 million and $13.5 million, respectively, which bear interest at the rate of 8.875%

 

712,460

 

711,512

 

Series B secured note assumed in the Eunice transaction, which bore interest at the rate of 9.5%

 

 

7,058

 

 

 

764,460

 

718,570

 

Less current portion

 

 

(7,058

)

Debt classified as long-term

 

$

764,460

 

$

711,512

 

 

8



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

Credit Facility. As of June 30, 2011, there was $71.3 million in outstanding letters of credit and $52.0 million borrowed under the Partnership’s bank credit facility, leaving approximately $361.7 million available for future borrowing based on the borrowing capacity of $485.0 million.

 

In July 2011, the Partnership amended its bank credit facility. The amendment to the Partnership’s credit facility, among other things, (i) permitted Apache Midstream LLC (“Apache”) to have a first priority lien on certain assets that are the subject of a joint interest arrangement between Apache and Crosstex Permian, LLC (“Permian”) (including a new-build natural gas processing facility and related assets in the Permian Basin in West Texas) to secure obligations that Permian would owe to Apache should Permian fail to fund its obligations pursuant to the joint interest arrangement and (ii) increased the Partnership’s ability to make investments in joint ventures and subsidiaries without such joint ventures and subsidiaries becoming guarantors under the credit agreement.

 

In May 2011, the Partnership amended its bank credit facility. The borrowing capacity under the credit facility was increased from $420.0 million to $485.0 million and the maturity was extended from February 2014 to May 2016. Additionally, the amendment to the Partnership’s credit facility, among other things, (i) increased the maximum permitted leverage ratios during certain fiscal quarters, (ii) decreased the minimum consolidated interest rate coverage ratio during certain fiscal quarters and (iii) decreased the interest rate the Partnership pays on the obligations under the credit facility. Also under the amended credit facility, the Partnership increased the accordian from $100.0 million to $150.0 million, which permits the Partnership to increase its borrowing capacity if any bank in the credit facility or a new bank is willing to undertake such commitment.

 

The credit facility is guaranteed by substantially all of the Partnership’s subsidiaries and is secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in substantially all of its subsidiaries and its interest in HEP.

 

The Partnership may prepay all loans under the amended credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

 

Under the amended credit facility, borrowings bear interest at the Partnership’s option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The Partnership pays a per annum fee (as described below) on all letters of credit issued under the amended credit facility and a commitment fee of between 0.375% and 0.50% per annum on the unused availability under the amended credit facility. The commitment fee, letter of credit fee and the applicable margins for the interest rate vary quarterly based on the Partnership’s leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:

 

 

 

Base Rate

 

Eurodollar
Rate

 

Letter of Credit

 

Leverage Ratio 

 

Loans

 

Loans

 

Fees

 

Greater than or equal to 4.50 to 1.00

 

2.00

%

3.00

%

3.00

%

Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00

 

1.75

%

2.75

%

2.75

%

Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00

 

1.50

%

2.50

%

2.50

%

Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00

 

1.25

%

2.25

%

2.25

%

Less than 3.00 to 1.00

 

1.00

%

2.00

%

2.00

%

 

9



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

The amended credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.

 

The maximum permitted leverage ratio is 4.75 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

 

The maximum permitted senior leverage ratio (as defined in the credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges), is 2.75 to 1.00.

 

The minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is as follows:

 

·                       2.25 to 1.00 for the fiscal quarters ending September 30, 2011, December 31, 2011, March 31, 2012 and June 30, 2012;

 

·                       2.50 to 1.00 for September 30, 2012 and each fiscal quarter thereafter.

 

All other material terms of the credit facility are described in the Company’s Annual Report on Form 10-K filing for the year ended December 31, 2010. The Company expects to be in compliance with all credit facility covenants for at least the next twelve months.

 

Series B Secured Note. On October 20, 2009, the Partnership acquired the Eunice natural gas liquids processing plant and fractionation facility which included an $18.1 million series B secured note. The note bears interest at a rate of 9.5%. The Partnership paid $11.0 million of principal of the series B secured note in May 2010 and paid the remaining $7.1 million in May 2011.

 

(3) Other Long-term Liabilities

 

Prior to January 1, 2011, the Partnership entered into 9 and 10-year capital leases for certain equipment. Assets under capital leases as of June 30, 2011 are summarized as follows (in thousands):

 

Compressor equipment

 

$

37,199

 

Less: Accumulated amortization

 

(8,636

)

Net assets under capital lease

 

$

28,563

 

 

The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of June 30, 2011 (in thousands):

 

2011

 

$

2,291

 

2012 through 2015 ($4,582 annually)

 

18,328

 

Thereafter

 

16,680

 

Less: Interest

 

(7,435

)

Net minimum lease payments under capital lease

 

29,864

 

Less: Current portion of net minimum lease payments

 

(4,448

)

Long-term portion of net minimum lease payments

 

$

25,416

 

 

(4)      Certain Provisions of the Partnership Agreement

 

Unless restricted by the terms of the Partnership’s credit facility, the Partnership must make distributions of 100.0% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98.0% to the common unitholders and 2.0% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved.

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23.0% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit. Incentive distributions totaling $0.6 million and $1.0 million were earned by the Company for the three and six months ended June 30, 2011, respectively.  No incentive distributions were earned by the general partner for the three and six months ended June 30, 2010.

 

The Partnership’s first quarter 2011 distribution on its common and preferred units of $0.29 per unit was paid on May 13, 2011.  The Partnership increased its second quarter 2011 distribution on its common and preferred units to $0.31 per unit to be paid on August 12, 2011.

 

(5) Earnings per Share and Dilution Computations

 

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three and six months ended June 30, 2011 and 2010.  The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares.  All common share equivalents were antidilutive in the three and six months ended June 30, 2011 and June 30, 2010 because the Company had a net loss for the periods.

 

The following table reflects the computation of basic earnings per share for the periods presented (in thousands except per share amounts):

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,073

)

$

(2,181

)

$

(2,609

)

(7,583

)

Distributed earnings allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

4,239

 

$

 

$

8,002

 

$

 

Unvested restricted shares

 

115

 

 

190

 

 

Total distributed earnings

 

$

4,354

 

$

 

$

8,192

 

$

 

Undistributed loss allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

(5,281

)

$

(2,118

)

$

(10,546

)

$

(7,367

)

Unvested restricted shares

 

(146

)

(63

)

(255

)

(216

)

Total undistributed loss

 

$

(5,427

)

$

(2,181

)

$

(10,801

)

$

(7,583

)

Net loss allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

(1,042

)

$

(2,118

)

$

(2,544

)

$

(7,367

)

Unvested restricted shares

 

(31

)

(63

)

(65

)

(216

)

Total net loss

 

$

(1,073

)

$

(2,181

)

$

(2,609

)

$

(7,583

)

Basic and diluted net loss per share:

 

 

 

 

 

 

 

 

 

Basic common share

 

$

(0.02

)

$

(0.05

)

$

(0.05

)

$

(0.16

)

Diluted common share

 

(0.02

)

(0.05

)

(0.05

)

(0.16

)

 

The following are the common share amounts used to compute the basic and diluted earnings per common share for the three and six months ended June 30, 2011 and 2010 (in thousands):

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Basic and diluted weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding

 

47,140

 

46,598

 

47,108

 

46,571

 

 

(6) Employee Incentive Plans

 

(a)         Long-Term Incentive Plans

 

The Company accounts for share-based compensation in accordance with FASB ASC 718, which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.

 

The Company and the Partnership each have similar unit or share-based payment plans for employees, which are described below.  Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Cost of share-based compensation charged to general and administrative expense

 

$

1,596

 

$

2,342

 

$

3,386

 

$

4,503

 

Cost of share-based compensation charged to operating expense

 

265

 

443

 

729

 

864

 

Total amount charged to income

 

$

1,861

 

$

2,785

 

$

4,115

 

$

5,367

 

Interest of non-controlling partners in share-based compensation

 

$

763

 

$

1,105

 

$

1,672

 

$

2,137

 

Amount of related income tax benefit recognized in income

 

$

407

 

$

623

 

$

906

 

$

1,198

 

 

(b) Partnership Restricted Units

 

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the six months ended June 30, 2011 is provided below:

 

 

 

Six Months Ended June 30, 2011

 

 

 

Number of

 

Weighted
Average
Grant-Date

 

Crosstex Energy, L.P. Restricted Units:

 

Units

 

Fair Value

 

Non-vested, beginning of period

 

1,047,374

 

$

10.30

 

Granted

 

289,800

 

15.16

 

Vested*

 

(391,543

)

14.19

 

Forfeited

 

(23,518

)

14.51

 

Non-vested, end of period

 

922,113

 

$

10.07

 

Aggregate intrinsic value, end of period (in thousands)

 

$

16,736

 

 

 

 


* Vested units include 113,241 units withheld for payroll taxes paid on behalf of employees.

 

The Partnership issued restricted units in 2011 to officers and other employees. These restricted units typically vest at the end of three years and are included in the restricted units outstanding and the current share-based compensation cost calculations at June 30, 2011.

 

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and six months ended June 30, 2011 and 2010 are provided below (in thousands):

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Crosstex Energy, L.P. Restricted Units:

 

2011 

 

2010 

 

2011 

 

2010

 

Aggregate intrinsic value of units vested

 

$

1,870

 

$

783

 

$

6,109

 

$

7,099

 

Fair value of units vested

 

$

2,383

 

$

337

 

$

5,556

 

$

2,856

 

 

As of June 30, 2011, there was $6.3 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2 years.

 

(c) Partnership Unit Options

 

A summary of the unit option activity for the six months ended June 30, 2011 is provided below:

 

 

 

Six Months Ended June 30, 2011

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, L.P. Unit Options:

 

Units

 

Exercise Price

 

Outstanding, beginning of period

 

611,311

 

$

6.77

 

Exercised

 

(85,409

)

4.69

 

Forfeited

 

(14,539

)

7.20

 

Expired

 

 

 

Outstanding, end of period

 

511,363

 

$

7.14

 

Options exercisable at end of period

 

367,156

 

 

 

Weighted average contractual term (years) end of period:

 

 

 

 

 

Options outstanding

 

7.7

 

 

 

Options exercisable

 

7.4

 

 

 

Aggregate intrinsic value end of period (in thousands):

 

 

 

 

 

Options outstanding

 

$

6,162

 

 

 

Options exercisable

 

$

4,410

 

 

 

 

A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units vested (value per Black-Scholes-Merton option pricing model at date of grant) during the three and six months ended June 30, 2011 and June 30, 2010 are provided below (in thousands):

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

Crosstex Energy, L.P. Unit Options:

 

2011

 

2010

 

2011

 

2010

 

Intrinsic value of unit options exercised

 

$

479

 

$

130

 

$

985

 

$

289

 

Fair value of units vested

 

$

236

 

$

259

 

$

561

 

$

294

 

 

As of June 30, 2011, there was $0.4 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted average period of 1.5 years.

 

(d)      Crosstex Energy, Inc.’s Restricted Stock

 

The Company’s restricted shares are included at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activities for the six months ended June 30, 2011 is provided below:

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

 

 

Six Months Ended

 

 

 

June 30, 2011

 

Crosstex Energy, Inc. Restricted Shares:

 

Number of
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

Non-vested, beginning of period

 

1,108,998

 

$

8.64

 

Granted

 

472,343

 

8.65

 

Vested*

 

(392,452

)

13.46

 

Forfeited

 

(28,407

)

10.61

 

Non-vested, end of period

 

1,160,482

 

$

6.96

 

Aggregate intrinsic value, end of period (in thousands)

 

$

13,810

 

 

 

 


* Vested shares include 109,032 shares withheld for payroll taxes paid on behalf of employees.

 

CEI issued restricted shares in 2011 to officers and other employees. These restricted shares typically vest at the end of three years and are included in restricted shares outstanding and the current share-based compensation cost calculations at June 30, 2011.

 

A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value of shares vested (market value at date of grant) during the three and six months ended June 30, 2011 and June 30, 2010 are provided below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Crosstex Energy, Inc. Restricted Shares:

 

2011

 

2010

 

2011

 

2010

 

Aggregate intrinsic value of shares vested

 

$

1,111

 

$

498

 

$

3,689

 

$

813

 

Fair value of shares vested

 

$

2,391

 

$

311

 

$

5,281

 

$

1,337

 

 

As of June 30, 2011 there was $5.5 million of unrecognized compensation costs related to CEI non-vested restricted shares. The cost is expected to be recognized over a weighted average period of 2 years.

 

(e)       Crosstex Energy, Inc.’s Stock Options

 

CEI stock options have not been granted as a means of compensation since 2005. All options outstanding at December 31, 2009 were vested and exercisable with all associated costs recognized.  The following is a summary of the CEI stock options outstanding as of June 30, 2011:

 

 

 

Six Months Ended June 30, 2011

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, Inc. Stock Options:

 

Shares

 

Exercise Price

 

Outstanding, beginning of period

 

37,500

 

$

6.50

 

Forfeited

 

 

 

Outstanding, end of period

 

37,500

 

$

6.50

 

Options exercisable at end of period

 

37,500

 

$

6.50

 

Weighted average contractual term (years) end of period

 

3.5

 

 

 

 

(7) Derivatives

 

Commodity Swaps

 

The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risks related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.

 

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Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

The Partnership commonly enters into various derivative financial transactions which it does not designate as accounting hedges. These transactions include “swing swaps,” “third party on-system financial swaps,” “storage swaps,” “basis swaps,” “processing margin swaps,” and “put options.”  Swing swaps are generally short-term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Third party on-system financial swaps are hedges that the Partnership enters into on behalf of its customers who are connected to its systems, wherein the Partnership fixes a supply or market price for a period of time for its customers, and simultaneously enters into the derivative transaction. Storage swap transactions protect against changes in the value of products that the Partnership has stored to serve various operational requirements (gas) or has in inventory due to short term constraints in moving the product to market (liquids). Basis swaps are used to hedge basis location price risk due to buying gas into one of the Partnership’s systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge fractionation spread risk at the Partnership’s processing plants relating to the option to process versus bypassing the Partnership’s equity gas.  Put options are purchased to hedge against declines in pricing and as such represent options, not obligations, to sell the related underlying volumes at a fixed price.

 

The components of loss on derivatives in the condensed consolidated statements of operations relating to commodity swaps are (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Change in fair value of derivatives that do not qualify for hedge accounting

 

$

(825

)

$

(2,863

)

$

730

 

$

(515

)

Realized losses on derivatives

 

2,368

 

4,458

 

4,128

 

5,866

 

Ineffective portion of derivatives qualifying for hedge accounting

 

(101

)

(1

)

(82

)

(61

)

Net losses related to commodity swaps

 

$

1,442

 

$

1,594

 

$

4,776

 

$

5,290

 

Put option premium mark to market

 

94

 

 

181

 

 

Losses on derivatives

 

$

1,536

 

$

1,594

 

$

4,957

 

$

5,290

 

 

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in thousands):

 

 

 

June 30,

 

December 31,

 

 

 

2011

 

2010

 

Fair value of derivative assets — current, designated

 

$

42

 

$

1

 

Fair value of derivative assets — current, non-designated

 

4,769

 

5,522

 

Fair value of derivative assets — long term, designated

 

44

 

 

Fair value of derivative assets — long term, non-designated

 

44

 

1,169

 

Fair value of derivative liabilities — current, designated

 

(1,443

)

(1,066

)

Fair value of derivative liabilities — current, non-designated

 

(6,860

)

(6,914

)

Fair value of derivative liabilities — long term, designated

 

(72

)

 

Fair value of derivative liabilities — long term, non-designated

 

(113

)

(1,156

)

Net fair value of derivatives

 

$

(3,589

)

$

(2,444

)

 

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets as of June 30, 2011 (all gas volumes are expressed in MMBtu’s and liquids volumes are expressed in gallons). The remaining term of the contracts extend no later than December 2012 for derivatives. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

 

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Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

 

 

June 30, 2011

 

Transaction Type

 

Volume

 

Fair Value

 

 

 

(In thousands)

 

 

 

Cash Flow Hedges:*

 

 

 

 

 

Liquids swaps (short contracts)

 

(9,954

)

$

(1,429

)

Total swaps designated as cash flow hedges

 

 

 

$

(1,429

)

 

 

 

 

 

 

Mark to Market Derivatives:*

 

 

 

 

 

Swing swaps (short contracts)

 

(5,109

)

$

2

 

Physical offsets to swing swap transactions (long contracts)

 

5,109

 

9

 

 

 

 

 

 

 

Basis swaps (long contracts)

 

15,135

 

3,649

 

Physical offsets to basis swap transactions (short contracts)

 

(155

)

564

 

Basis swaps (short contracts)

 

(13,905

)

(3,548

)

Physical offsets to basis swap transactions (long contracts)

 

155

 

(663

)

 

 

 

 

 

 

Processing margin hedges — liquids (short contracts)

 

(14,967

)

(2,134

)

Processing margin hedges — gas (long contracts)

 

1,799

 

(208

)

Processing margin hedges — gas (short contracts)

 

(86

)

13

 

 

 

 

 

 

 

Storage swap transactions — gas (short contracts)

 

(70

)

23

 

Storage swap transactions — liquids inventory (short contracts)

 

(5,460

)

121

 

 

 

 

 

 

 

Liquid put options (purchased)

 

5,552

 

12

 

Total mark to market derivatives

 

 

 

$

(2,160

)

 


*                 All are gas contracts, volume in MMBtu’s, except for liquids swaps, processing margin hedges - liquids, storage swaps — liquids inventory and liquid put options (volume in gallons).

 

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of June 30, 2011 of $5.4 million would be reduced to $2.3 million due to the netting feature, all of which relates to other energy companies.

 

Impact of Cash Flow Hedges

 

The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the condensed consolidated statements of operations is summarized below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Increase (Decrease) in Midstream Revenue

 

2011

 

2010

 

2011

 

2010

 

Liquids

 

$

(1,048

)

$

(268

)

$

(1,708

)

$

(1,110

)

Realized loss included in Midstream revenue

 

$

(1,048

)

$

(268

)

$

(1,708

)

$

(1,110

)

 

Natural Gas

 

As of June 30, 2011, the Partnership has no balances in accumulated other comprehensive income related to natural gas.

 

16



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

Liquids

 

As of June 30, 2011, an unrealized derivative fair value net loss of $1.3 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive loss,  all of which is expected to be reclassified into earnings through June 2012. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected in the above table.

 

Derivatives Other Than Cash Flow Hedges

 

Assets and liabilities related to third party derivative contracts, swing swaps, basis swaps, storage swaps, processing margin swaps and put options purchased are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as (gain) loss on derivatives in the condensed consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

 

 

 

 

Maturity Periods

 

 

 

Less than one year

 

One to two years

 

More than two years

 

Total fair value

 

June 30, 2011

 

$

(2,091

)

$

(69

)

$

 

$

(2,160

)

 

(8)      Fair Value Measurements

 

FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

 

FASB ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

 

The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

 

Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in thousands):

 

 

 

June 30, 2011

 

December 31, 2010

 

 

 

Level 2

 

Level 2

 

Commodity Swaps*

 

$

(3,589

)

$

(2,444

)

Total

 

$

(3,589

)

$

(2,444

)

 


*                 Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date.  The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

 

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Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

Fair Value of Financial Instruments

 

The estimated fair value of the Company’s financial instruments has been determined by the Company using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Company could realize upon the sale or refinancing of such financial instruments (in thousands):

 

 

 

June 30, 2011

 

December 31, 2010

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

 

 

Value

 

Value

 

Value

 

Value

 

Long-term debt

 

$

764,460

 

$

827,750

 

$

718,570

 

$

768,308

 

Obligations under capital lease

 

$

29,864

 

$

27,700

 

$

31,327

 

$

28,807

 

 

The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

 

The Partnership had $52.0 million in borrowings under its revolving credit facility included in long-term debt as of June 30, 2011 and no borrowing at December 31, 2010 and accrued interest under floating interest rate structures. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2011 and December 31, 2010, the Partnership also had borrowings totaling $712.5 million and $711.5 million, net of discount, respectively, under senior unsecured notes with a fixed rate of 8.875% and a series B secured note with a principal amount of  $7.1 million as of December 31, 2010 with a fixed rate of 9.5%. The fair value of the senior unsecured notes as of June 30, 2011 and December 31, 2010 was based on third party market quotations. The fair value of the series B secured note as of December 31, 2010 was adjusted to reflect current market interest rates for such borrowings on that date.

 

(9) Income Tax

 

The Company has recorded a deferred tax asset in the amount of $20.5 million relating to the difference between its book and tax basis of its investment in the Partnership as of June 30, 2011 and December 31, 2010.  Because the Company can only realize this deferred tax asset upon the liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset.  The income tax provision for the six months ended June 30, 2011 reflects a tax benefit of  $0.9 million for the current period loss. Unrecognized tax benefits increased $0.2 million during the six months ended June 30, 2011, and the increase, if recognized, would affect the effective tax rate.

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

(10) Commitments and Contingencies

 

(a) Employment and Severance Agreements

 

Certain members of management of the Company are parties to employment and/or severance agreements with the general partner of the Partnership. The employment and severance agreements provide those managers with severance payments in certain circumstances and, in the case of employment agreements, prohibit each such person from competing with the general partner of the Partnership or its affiliates for a certain period of time following the termination of such person’s employment.

 

(b) Environmental Issues

 

The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third party company pursuant to which the remediation costs associated with these sites have been assumed by this third party company that specializes in remediation work. The Partnership does not expect to incur any material liability with these sites; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.

 

In addition, the Partnership disclosed possible Clean Air Act monitoring deficiencies it has discovered to the Louisiana Department of Environmental Quality (LDEQ) and is working with the agency to correct these deficiencies and to address modifications to facilities to ensure compliance. The Partnership does not expect to incur any material environmental liability associated with these issues.

 

In  May 2011, the Partnership received a Notice of Enforcement from the Texas Commission of Environmental Quality for an alleged violation of the Clean Air Act with one of the Partnership’s North Texas compressor station sites.  The Partnership does not expect to incur a material adverse effect as a result of this alleged violation.

 

(c) Other

 

The Company is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

 

On June 7, 2010, Formosa Plastics Corporation, Texas, Formosa Plastics Corporation, America, Formosa Utility Venture, Ltd., and Nan Ya Plastics Corporation, America filed a lawsuit against Crosstex Energy, Inc., Crosstex Energy, L.P., Crosstex Energy GP, L.P., Crosstex Energy GP, LLC, Crosstex Energy Services, L.P., and Crosstex Gulf Coast Marketing, Ltd. in the 24th Judicial District Court of Calhoun County, Texas, asserting claims for negligence, res ipsa loquitor, products liability and strict liability relating to the alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership.  The lawsuit alleges that the plaintiffs have incurred at least $65.0 million in damages, including damage to equipment and lost profits.  The Partnership has submitted the claim to its insurance carriers and intends to vigorously defend the lawsuit.  The Partnership believes that any recovery would be within applicable policy limits. Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

 

At times, the Partnership’s gas-utility subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain provided under state law. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

 

The Partnership (or its subsidiaries) is defending a number of lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.

 

(11) Segment Information

 

Identification of operating segments is based principally upon regions served.  The Partnership’s reportable segments consist of the natural gas gathering, processing and transmission operations located in north Texas (NTX), the pipelines and processing plants located in Louisiana (LIG) and the south Louisiana processing and NGL assets (PNGL). Operating activity for assets sold in the comparative periods that was not considered discontinued operations as well as intersegment eliminations is shown in the corporate segment.

 

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general partnership expenses associated with managing all reportable operating segments and the Company’s general and administrative expenses, including the Partnership’s general and administrative expenses. Corporate assets consist of property and equipment, including software, for general corporate support, working capital, debt financing costs, and the investment in HEP.

 

Summarized financial information concerning the Partnership’s reportable segments as consolidated into the Company’s condensed financial statements is shown in the following table.

 

 

 

LIG

 

NTX

 

PNGL

 

Corporate

 

Totals

 

 

 

(In thousands)

 

Three Months Ended June 30, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

219,272

 

$

87,813

 

$

189,062

 

$

 

$

496,147

 

Sales to affiliates

 

23,935

 

21,295

 

 

(45,230

)

 

Purchased gas and NGLs

 

(211,417

)

(64,360

)

(169,042

)

45,230

 

(399,589

)

Operating expenses

 

(8,902

)

(12,108

)

(6,903

)

 

(27,913

)

Segment profit

 

$

22,888

 

$

32,640

 

$

13,117

 

$

 

$

68,645

 

Gain (loss) on derivatives

 

$

(1,269

)

$

(377

)

$

110

 

$

 

$

(1,536

)

Depreciation, amortization and impairments

 

$

(4,045

)

$

(18,744

)

$

(7,828

)

$

(1,037

)

$

(31,654

)

Capital expenditures

 

$

1,129

 

$

16,807

 

$

5,555

 

$

715

 

$

24,206

 

Identifiable assets

 

$

327,174

 

$

1,112,750

 

$

492,920

 

$

78,345

 

$

2,011,189

 

Three Months Ended June 30, 2010:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

244,146

 

$

86,464

 

$

111,438

 

$

 

$

442,048

 

Sales to affiliates

 

19,420

 

19,800

 

1,308

 

(40,528

)

 

Purchased gas and NGLs

 

(233,729

)

(65,459

)

(99,378

)

40,528

 

(358,038

)

Operating expenses

 

(7,805

)

(11,214

)

(6,405

)

 

(25,424

)

Segment profit

 

$

22,032

 

$

29,591

 

$

6,963

 

$

 

$

58,586

 

Gain (loss) on derivatives

 

$

906

 

$

(2,693

)

$

193

 

$

 

$

(1,594

)

Depreciation, amortization and impairments

 

$

(3,051

)

$

(15,048

)

$

(7,933

)

$

(1,121

)

$

(27,153

)

Capital expenditures

 

$

4,972

 

$

2,692

 

$

851

 

$

266

 

$

8,781

 

Identifiable assets

 

$

336,407

 

$

1,122,796

 

$

475,724

 

$

51,553

 

$

1,986,480

 

Six Months Ended June 30, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

423,705

 

$

168,779

 

$

353,978

 

$

 

$

946,462

 

Sales to affiliates

 

46,742

 

42,880

 

 

(89,622

)

 

Purchased gas and NGLs

 

(406,920

)

(127,519

)

(315,251

)

89,622

 

(760,068

)

Operating expenses

 

(16,969

)

(23,460

)

(12,528

)

 

(52,957

)

Segment profit

 

$

46,558

 

$

60,680

 

$

26,199

 

$

 

$

133,437

 

Gain (loss) on derivatives

 

$

(3,954

)

$

(1,094

)

$

91

 

$

 

$

(4,957

)

Depreciation, amortization and impairments

 

$

(7,205

)

$

(36,464

)

$

(15,541

)

$

(2,116

)

$

(61,326

)

Capital expenditures

 

$

2,679

 

$

35,011

 

$

9,636

 

$

1,202

 

$

48,528

 

Identifiable assets

 

$

327,174

 

$

1,112,750

 

$

492,919

 

$

78,346

 

$

2,011,189

 

Six Months Ended June 30, 2010:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

489,504

 

$

196,598

 

$

224,604

 

$

 

$

910,706

 

Sales to affiliates

 

41,134

 

45,591

 

2,839

 

(89,564

)

 

Purchased gas and NGLs

 

(473,026

)

(163,755

)

(198,284

)

89,564

 

(745,501

)

Operating expenses

 

(16,264

)

(23,267

)

(12,358

)

 

(51,889

)

Segment profit

 

$

41,348

 

$

55,167

 

$

16,801

 

$

 

$

113,316

 

Gain (loss) on derivatives

 

$

(904

)

$

(4,507

)

$

121

 

$

 

$

(5,290

)

Depreciation, amortization and impairments

 

$

(6,072

)

$

(31,104

)

$

(15,828

)

$

(2,257

)

$

(55,261

)

Capital expenditures

 

$

5,902

 

$

5,380

 

$

920

 

$

681

 

$

12,883

 

Identifiable assets

 

$

336,407

 

$

1,122,796

 

$

475,724

 

$

51,553

 

$

1,986,480

 

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

The following table reconciles the segment profits reported above to the operating income as reported in the condensed consolidated statements of operations (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Segment profits

 

$

68,645

 

$

58,586

 

$

133,437

 

$

113,316

 

General and administrative expenses

 

(13,272

)

(12,455

)

(25,754

)

(25,936

)

Loss on derivatives

 

(1,536

)

(1,594

)

(4,957

)

(5,290

)

Gain (loss) on sale of property

 

60

 

(564

)

80

 

13,779

 

Depreciation, amortization and impairments

 

(31,654

)

(27,153

)

(61,326

)

(55,261

)

Operating income

 

$

22,243

 

$

16,820

 

$

41,480

 

$

40,608

 

 

(12) Subsequent Event

 

Subsequent to the quarter ended June 30, 2011 and prior to the issuance of the unaudited condensed consolidated financial statements, the Company evaluated and found no other events material to the financial statement presentation during this period.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

 

Overview

 

Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs) through its subsidiaries. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, processing, transmission and marketing of natural gas and NGLs.  These partnership interests consist of (i) 16,414,830 common units, representing approximately 25.0% of the limited partner interests in Crosstex Energy, L.P., and (ii) 100% ownership interest in Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

 

Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Unless restricted by the terms of the Partnership’s credit facility and/or senior unsecured note indenture, the Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.

 

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries.  We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own.  Our condensed consolidated results of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operation.  Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

 

The Partnership’s primary focus is on the gathering, processing, transmission and marketing of NGLs, which it manages in regional reporting segments of midstream activity.  The Partnership’s geographic focus is in the north Texas Barnett Shale (NTX) and in Louisiana which has two reportable business segments (LIG system and the south Louisiana processing and NGL assets, or PNGL).  The Partnership’s recently announced expansion project with Apache Corporation will also give the Partnership a presence in the Permian Basin in west Texas, and the Partnership’s recent investment in HEP gives the Partnership access to activity in the Eagle Ford Shale in south Texas as described in more detail in the Recent Developments section below.  The Partnership manages its operations by focusing on gross operating margin because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport or market natural gas and NGLs for a fee. We define gross operating margin as operating revenue minus cost of purchased gas and NGLs.

 

The Partnership’s gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, and the volumes of NGLs handled at its fractionation facilities. The Partnership generates revenues from four primary sources:

 

·                  purchasing and reselling or transporting natural gas on the pipeline systems it owns;

 

·                  processing natural gas at its processing plants;

 

·                  fractionating and marketing the recovered NGLs; and

 

·                  providing compression services.

 

The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the market index. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction.  The Partnership’s gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas.  The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies

 

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purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion the Partnership has entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as margin. Changes in the basis spread can increase or decrease margins.

 

One contract (the “Delivery Contract”) has a term to 2019 that obligates the Partnership to supply approximately 150,000 MMBtu/d of gas.  At the time that the Partnership entered into the Delivery Contract in 2008, it had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract.  The Partnership’s agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of its sales price for such gas less certain fees and costs.  Accordingly, the Partnership was initially able to generate a positive margin under the Delivery Contract.  However, since entering into the Delivery Contract, there has been both (1) a reduction in the gas available under the supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to east coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract.  Due to these factors, the Partnership has had to purchase a portion of the gas necessary to fulfill its obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

 

The Partnership has recorded a loss of approximately $6.0 million during the six months ended June 30, 2011 on the Delivery Contract.  The Partnership currently expects that it will record an additional loss of approximately $6.0 million to $8.0 million on the Delivery Contract for the remainder of the year ending December 31, 2011.  This estimate is based on forward prices, basis spreads and other market assumptions as of June 30, 2011. These assumptions are subject to change if market conditions change during the remainder of 2011, and actual results under the Delivery Contract in 2011 could be substantially different from the Partnership’s current estimates, which may result in a greater loss than currently estimated.

 

The Partnership also realizes gross operating margins from its processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements the Partnership’s gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Under fixed-fee based contracts the Partnership’s gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

 

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges, and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas or liquids moved through the asset.

 

Recent Developments

 

Investment in Limited Liability Company.  On June 22, 2011, the Partnership entered into a limited liability agreement with HEP for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP of approximately 35.0%.  In addition to the Partnership’s contribution, an unrelated party also provided a capital contribution of $35.0 million for a 35.0% ownership in HEP with HEP management and a few private investors owning the remaining 30.0% interest.  HEP will operate and manage midstream services as well as pipeline and plant construction primarily in the Eagle Ford Shale in south Texas.

 

Credit Facility. On May 2, 2011 and July 11, 2011, the Partnership amended its bank credit facility. The May 2011 amendment increased its borrowing capacity from $420.0 million to $485.0 million, reduced interest rates and improved terms of other covenants under the facility. The July 2011 amendment permitted a first priority lien on certain assets that are associated with the Partnership’s joint interest arrangement with Apache and increased the Partnership’s ability to make investments in joint ventures and subsidiaries without such joint ventures and subsidiaries becoming guarantors under the credit agreement. See Note (2) to the condensed consolidated financial statements for a discussion of the amended terms.

 

Asset Expansions.  The Partnership completed two expansion projects discussed more fully below on its natural gas gathering system in the Barnett Shale play in North Texas that became operational in March 2011.  The Partnership also reactivated its Eunice NGL fractionators  in south central Louisiana to give the Partnership operational flexibility, increase the Partnership’s fractionation

 

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capacity and  give the Partnership the ability to capture new NGL-related business. The Eunice NGL fractionators became operational in early April 2011 and are equipped to accommodate 15,000 of NGLs per day (“Bbls/d”).

 

The Partnership expanded its natural gas gathering system in North Texas with the construction of a $25.0 million, 15-mile pipeline extension to serve major Barnett Shale producers.  The project, which is supported by volumetric commitments, includes a seven-mile low-pressure pipeline, an eight-mile high-pressure pipeline and a compressor station in southwest Tarrant County that provides customers with greater takeaway capacity to accommodate their transportation requirements.

 

The Partnership also entered into a 10-year firm gathering and compression agreement with a major Barnett Shale producer for an additional 50 MMcf/d on its North Texas gathering system.  The Partnership constructed a compressor station on an existing gathering line to accommodate the customer’s transportation requirements.

 

Expansion into Permian Basin.  On July 11, 2011, the Partnership entered into an agreement with Apache  to jointly invest $85.0 million in a new natural gas processing facility in the Permian Basin in west Texas.  The Partnership will fund the processing project equally with Apache as the plant is constructed over the next twelve months and the Partnership will each hold a 50 percent undivided working interest in the plant. The Partnership will manage the construction and operation of the plant.  Separately, the Partnership will buy and upgrade a nearby rail terminal to provide transportation of  NGLs to the Partnership’s Eunice fractionation facility in southern Louisiana.

 

Pipeline Expansion.   On July 25, 2011, the Partnership announced that it is completing engineering studies, pipeline routing work and environmental permitting for a NGL project that will expand its Louisiana fractionation facilities and expand access to these facilities and Louisiana product markets through a new NGL pipeline. The new pipeline will be an extension of the Partnership’s 440-mile Cajun-Sibon NGL pipeline that is connected to the Partnership’s Eunice NGL fractionation facilities in south central Louisiana. The new 130-mile NGL pipeline extension will connect the Eunice fractionation facilities to Mont Belvieu supply pipelines and will have an initial capacity of 70,000 barrels per day of raw-make NGLs. The project also includes the expansion of the Partnership’s Eunice NGL fractionation facilities from 15,000 barrels to 55,000 barrels of NGL per day, which will increase the Partnership’s interconnected fractionation capacity in Louisiana to approximately 97,000 barrels per day of NGLs. The Partnership’s investment for the project is currently estimated at $180.0 million to $220.0 million over the next two years.

 

Also, the Partnership entered into a long-term ethane sales agreement with a third party providing a secure market for the key product in the project. The ethane will flow into the third party’s ethane pipeline system in Louisiana. In addition, the Partnership has its own supply from its Texas gas plants and commitments for supply from a select group of NGL suppliers.

 

Non-GAAP Financial Measures

 

We include the following non-generally accepted accounting principles, or non-GAAP, financial measures: The Partnership’s adjusted earnings before interest, taxes, depreciation and amortization, or EBITDA, and gross operating margin.

 

We define the Partnership’s adjusted EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense, impairments, stock-based compensation, loss on extinguishment of debt, (gain) loss on noncash derivatives, equity in loss of HEP and minority interest; less gain on sale of property. The Partnership’s adjusted EBITDA is used as a supplemental performance measure by its management and by external users of its financial statements such as investors, commercial banks, research analysts and others, to assess:

 

·                  financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis;

 

·                  the ability of the Partnership’s assets to generate cash sufficient to pay interest costs, support its indebtedness and make cash distributions to its unitholders and the general partner;

 

·                  the Partnership’s operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

 

·                  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

 

The Partnership’s adjusted EBITDA is one of the critical inputs into the financial covenants within the Partnership’s credit facility. The rates the Partnership pays for borrowings under its credit facility are determined by the ratio of its debt to the

 

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Partnership’s adjusted EBITDA.  The calculation of these ratios allows for further adjustments to the Partnership’s adjusted EBITDA for recent acquisitions and dispositions.

 

The Partnership’s adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. The adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA in the same manner.

 

The Partnership’s adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because the Partnership has borrowed money to finance its operations, interest expense is a necessary element of its costs and its ability to generate cash available for distribution. Because the Partnership uses capital assets, depreciation and amortization are also necessary elements of its costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as the Partnership’s adjusted EBITDA, to evaluate the Partnership’s overall performance.

 

The following table provides a reconciliation of the Company’s net loss to the Partnership’s adjusted EBITDA:

 

 

 

Three Months Ended June 30,